This invention relates to a rotary drill bit for drilling oil and gas wells in the earth, and more particularly to a rotary drill bit comprising generally conical roller cutters having cutting elements thereon which engage and "drill" the formation.
Cutting elements may be of two principal types; namely (1) milled tooth type which are relatively long, wide teeth having tapering sides formed by machining a steel roller cutter body, and (2) insert type which are generally cylindrical studs or inserts of tungsten carbide material press fit into bores drilled in a steel roller cutter body. Rotary drill bits are characterized as either "milled tooth" bits or "insert" bits, depending on which type of cutting element is used. A conventional "milled tooth" bit is shown in U.S. Pat. No. 2,148,372 and a conventional "insert" bit is shown in U.S. Pat. No. 2,687,875.
Roller cone rotary drill bits are the most widely used of the various kinds of oil field drill bits, because they offer satisfactory rates of penetration, as measured in feet per hour, in drilling most commonly encountered formations. Milled tooth bits, for example, present an aggressive cutting structure for providing relatively high rates of penetration in soft formations. Soft formations are typically encountered "high in the hole" (e.g., 0 to 5000 feet deep). Moreover, while the teeth are of steel and thus subject to relatively rapid wear due to abrasion by the formation and erosion by the high-velocity drilling fluid at the bottom of the well bore, the time required for tripping the drill string in and out of the well bore to replace a worn bit is relatively low. Accordingly, in drilling soft formations, the milled tooth bit's high rate of penetration outweighs its replacement cost (i.e., bit cost plus trip time cost).
In contrast, insert drill bits, which have relatively small tungsten carbide studs or inserts of generally cylindrical or conical shape having a blunt tip, are successful in drilling medium and hard formations. Such formations are typically encountered "deep in the hole". The success of insert drill bits in hard formations is due to the nature of the drilling action of such bits and their relatively long useful life as measured in the number of feet of formation drilled. As opposed to the teeth of milled tooth bits which drill principally by means of a dragging, scrapping or gouging action, insert bits drill by means of a compressive loading action in which the inserts apply high point loads to the formation. Medium and hard formations, which are typically brittle, crack or fracture in compression under such point loads. Moreover, tungsten carbide, from which the inserts are formed, has high compressive strength and abrasion resistance for extended bit life. In deep hole drilling, reducing the number of relatively time-consuming (and thus costly) trips for bit replacement is critical in reducing overall drilling costs.
In February, 1970, a new bit design was patented by P. W. Schumacher, Jr. (U.S. Pat. No. 3,495,668) which incorporated offset axis cutters to provide some measure gouging and scraping cutting action in the drill bit. A subsequent patent, U.S. Pat. No. 3,696,876, issued to Ott in October, 1972, also disclosed a similar invention wherein offset axis cutting elements were incorporated into an insert bit.
Drilling bits incorporating the novel combination of offset cutters and tungsten carbide inserts were successfully introduced by the assignee of the present invention, Reed Rock Bit Company, in 1970, and have become a commonly used type of drill bit in the drilling industry over the past ten years. This second generation of drill bits utilize offset axes and tungsten carbide insert and are particularly advantageous in soft to medium-soft formations by reason of their imparting of some measure of gouging and scraping action to the cutting action of the bit which enhances the drilling efficiency and rate of penetration of the bit in these formations. The amount of offset utilized in these bits ranges on the order of from about 1/64 to about 1/32 inch offset per inch of drill bit diameter. For instance, a 77/8 inch bit having offset would have from 1/8 inch to 1/4 inch total offset of the cutters.
Coventional drilling bits currently on the market are limited in the amount of offset introduced into the cutters to about 1/32 inch of offset per inch of diameter. Thus, the maximum amount of offset utilized in these soft formations bits currently runs about 1/4 inch in a 77/8 inch diameter bit. During this ten year period when offset axis insert bits have been made commercially successful, those skilled in the art of drill bit technology generally have followed the principle that any additional offset in the cutters above about 1/32 inch per inch of bit diameter would not add any significant efficiency or increased drilling rate to the bit, but would increase the tendency of inserts to fail under the shear forces such increased offset would introduce. Thus, those skilled in the art have restricted their insert bit designs to having an offset range of from zero to 1/32 inch per inch of bit diameter. In addition, as the amount of offset is increased and some measure of drag cutting action is imparted to the drill bit, there is an accompanying increased tendency of certain types of formations (i.e., so-called "sticky" formations) to adhere to the roller cutters. Over time, this can result in "bit-balling" in which a thick layer or coating of cut formation covers the roller cutters, limiting the depth of penetration of the cutting elements into the formation and reducing rates of drilling penetration.
Moreover, one drilling application for which neither conventional milled tooth nor insert bits have been satisfactory has been the deep hole drilling of medium and hard formations, such as Mancos shale and Colton sandstone, which become relatively ductile or plastically deformable under extreme "over balanced" conditions. Overbalance occurs when the hydrostatic pressure at the bottom of the column of drilling fluid in the well bore exceeds the pore pressure of the fluid in the formation surrounding the well bore bottom. This pressure differential causes certain otherwise brittle formations to become ductile. When a conventional insert bit is used to drill such formations, the inserts tend to deform rather than fracture the formation and thus the rate of penetration of the bit is relatively slow. When tooth bits are used to drill such a formation, they are rapidly worn and thus provide an unsatisfactory useful life. Moreover, over-balance tends to cause "chip hold down" in which cuttings from the formation are held at the well bore bottom rather than carried away by the drilling fluid.
Conventional nozzle systems are generally of two types. The oldest type, such as shown in U.S. Pat. No. 2,244,617, utilizes large, relatively unrestricted fluid openings in the bit body directly above the roller cutters to allow a low pressure flow of the drilling fluid to impinge directly on the roller cutter bodies and to flow around the roller cutters to the bottom of the borehole. By necessity, this is a low-volume, low-velocity flow since the fluid stream impinges directly upon the cutter face, and erosion of the cones by the fluid stream would be a serious problem under these circumstances. The second type of conventional bit fluid system comprises the "jet" bits. In a jet bit, a high velocity stream of fluid is directed by a nozzle in the bit body against the formation face without impinging any cutting elements or any other portion of the bit. Impingement of the steel roller cutter body by the stream would result in significant erosion. In some instances, the so-called jet bits have fluid nozzles extending from the bit bodies to a point only a fraction of an inch above the formation face to maximize the hydraulic energy of the fluid stream impinging the formation face. Thus, while the stream of drilling fluid may at least partially clean the formation before being engaged by the roller cutter, it does not clean the roller cutters.